1. Field of the Invention
This invention relates to the treatment of hydrocarbons and more specifically relates to separating and recovering ethane and higher boiling hydrocarbons from the methane in a natural gas stream which has been sweetened by removal of acidic components, such as CO.sub.2, H.sub.2 S, RSH, RSSR, and ammonia.
2. Review of the Prior Art
Raw natural gas as it originates from subterranean reservoirs, either out of solution from crude oil or unassociated with crude oil, can be classified as rich natural gas, rich gas, or lean natural gas. These terms are relative.
Rich natural gas contains a mixture of individual gaseous constituents, some of which can be liquified at atmospheric temperatures and pressures when isolated. The quantities of each component vary from one gas to another, with methane as a usual majority component. Other hydrocarbon components include ethane, propane, isobutane, normal butane, isopentane, normal pentane, hexane, heptane, octane, and nonane, in the order of increasing molecular weight and increasing boiling temperature. Usually, natural gases contain some gaseous contaminations such as nitrogen, carbon dioxide, carbonyl sulfide, hydrogen sulfide, mercaptans, disulfides, ammonia, and water. However, all of these impurities except water and nitrogen are removed by sweetening. Such a sweet natural gas stream is the subject of this invention.
"Lean natural gas" is a term applied to a natural gas which consists of only the lower molecular weight gaseous components, consisting for the most part of methane with variant quantities of ethane, propane, and only very small traces of higher molecular weight components, if any. Such a lean natural gas can occur naturally but generally results from processing a rich natural gas in accordance with recognized industrial methods.
Such a lean natural gas stream, if it contains a high proportion of ethane and propane, may be treated according to the method of this invention to produce desired quantities of these hydrocarbons.
The sweet natural gas stream which is preferably handled according to the method of this invention contains nitrogen, methane, ethane, propane, iso and normal butanes, iso and normal pentanes, hexane, heavier hydrocarbon components, and water. However, there are no acid gases or other acidic impurities, such as CO.sub.2, COS, H.sub.2 S, RSH, RSSR, and ammonia, unless a terminal treatment step is added to the process.
If a natural gas is mostly methane with minor concentrations of ethane, propane, and butanes, it is called a "dry gas", meaning that it has a very low hydrocarbon dew point. The larger the quantity of heavier hydrocarbons such as pentane and higher homologs, e.g., to C.sub.18, the higher is the hydrocarbon dew point. Frequently, the heavier hydrocarbons are present in sufficient quantities to justify passing the gas through a "gasoline extraction plant" which removes ethane and propane in addition to the heavier hydrocarbons. In some instances, the hydrocarbon dew point is high enough to require a "dew point control station" which removes enough of the heavy hydrocarbons to lower the dew point sufficiently to permit pipeline transmission but does not remove as much of the heavier materials, in addition to the large percentage of the propane and ethane, as is removed by a gasoline extraction plant. Furthermore, the gas coming from the wellhead is usually saturated with water which must be largely removed in order to prevent the formation of ice and hydrates or the accumulation of water which can block the flow and cause corrosion.
Numerous processes have been used to extract liquids from natural gas streams. These processes include oil absorption, refrigerated oil absorption, simple refrigeration, cascaded refrigeration, Joule-Thompson expansion, cryogenic turbo-expansion, and absorption by oxygen-containing liquids.
Oil absorption processes, such as that described in U.S. Pat. No. 2,428,521, are the original separation processes and commonly recover butanes plus heavier components, with some amounts of propane, from natural gas streams. Refrigerated oil absorption processes are similar to the absorption processes except that the oil is cooled by external refrigeration before absorption of liquid components from the gas streams. The recoveries of propane plus components are improved by cooling the absorption oil. Plants using these processes are extremely complex and energy extensive.
A simple refrigeration process includes cooling the gas directly with a single refrigerant, such as propane. Condensed liquids are separated from the gas and are pumped to product pipelines. The recoveries of a simple refrigeration system are better than those of oil absorption units. A cascaded refrigeration process includes several levels of refrigeration, using at least two refrigerants, such as ethane refrigerant cascaded into a propane refrigerant cycle. The recoveries of cascade refrigeration systems are quite good, but units using these processes are not very economical because of high operating and installing costs.
The Joule-Thompson process is a step forward because it uses the refrigeration from the components of a natural gas stream by letting down its pressure. When the residue gas is required at essentially the same pressure as the inlet gas, however, this process becomes quite expensive. A cryogenic expander process has less energy consumption than a Joule-Thompson process for a given recovery, primarily because a portion of the total recompression of residue gas is provided by the turbo-expander. The Joule-Thompson and cryogenic expander processes are primarily used when ethane is to be extracted from natural gas streams. These processes can achieve ethane recoveries as high as 85% to 90%.
In summary, the oil absorption, refrigerated oil absorption, simple refrigeration, and cascaded refrigeration processes operate at the pipeline pressures, without letting down the gas pressure, but the recovery of desirable liquids (ethane plus heavier components) is quite poor, with the exception of the cascaded refrigeration process which has extremely high operating costs but achieves good ethane and propane recoveries. The Joule-Thompson and cryogenic expander processes achieve high ethane recoveries by letting down the pressure of the entire inlet gas, which is primarily methane (typically 80-85%), but recompression of most of the inlet gas is quite expensive.
Under poor economic conditions when the liquid ethane price as petrochemical feedstock is less than its equivalent fuel price and when the propane price for feedstock usage is attractive, the operator of a natural gas liquid extraction plant would prefer to maximize the propane recovery while minimizing the ethane recovery but is limited in operating choice. The refrigeration process, which typically recovers 80% of the propane, requires the recovery of typically 35% of the ethane in the inlet gas. In order to boost propane recovery to the 95+% level, cascaded refrigeration, Joule-Thompson, cryogenic, and turbo-expander processes would be required simultaneously to boost the ethane recovery to 70+% at a considerably larger capital investment.
Absorption processes are available that employ liquids other than hydrocarbon oils for removal of acidic components including H.sub.2 S and CO.sub.2, water, and heavier hydrocarbons which are lost. These liquids comprise propylene carbonate, N-methyl pyrrolidone, glycerol triacetate, polyethyleneglycol dimethyl ether, triethylolamine, tributyl phosphate, and gamma butyrolactone. In particular, U.S. Pat. No. 3,362,133 is directed to sour natural gas mixtures containing H.sub.2 S and CO.sub.2 and teaches the selection of any dialkyl ether of a polyalkylene glycol as the ether component of a solvent for withdrawing H.sub.2 S. A mixture of six dimethyl ethers of polyethylene glycol (DMPEG) is said to be effective. The solvent/gas ratio is 0.1 to 1.8 pounds of solvent per standard cubit foot (scf) of H.sub.2 S to be absorbed because less than this amount will not effectively remove H.sub.2 S and larger amounts of CO.sub.2. The H.sub.2 S-rich and CO.sub.2 -rich DMPEG solvent is flashed at 15-500 psi lower pressure than in the absorber (preferably, 65 psi lower pressure) in a flash tank which produces gas having substantially all of the CO.sub.2 and one-fourth of the H.sub.2 S. This gas is returned to the absorber. The DMPEG solvent is heated, reduced in pressure, and passed through a packed column as air is passed upwardly. The solvent must contain no more than 0.001% H.sub.2 S when it returns to the absorber. The CO.sub.2 and H.sub.2 S which are vented from the top of the stripping column contain dissolved hydrocarbons which represent a significant loss.
U.S. Pat. No. 3,770,622 relates to treatment for natural gas to remove three troublesome components: CO.sub.2, H.sub.2 S, and hydrocarbons heavier than methane. The preferred solvent is propylene carbonate. Polyethylene glycol dimethyl ether may be passed in counter-flowing contact with a natural gas mixture to remove CO.sub.2 and/or H.sub.2 S acid gases plus C.sub.2 -C.sub.18 hydrocarbon components from methane gas streams. CO.sub.2, H.sub.2 S, and light hydrocarbons are partially separated from the solvent by flashing. Liquid hydrocarbons, C.sub.4 and heavier, having gasoline value are then separated in a settler from liquid solvent and from a vaporphase mixture of C.sub.2 -C.sub.12 hydrocarbon vapor, H.sub.2 S, and/or CO.sub.2. In the Example, the three flash streams together contain 43.76% of C.sub.2 -C.sub.12 hydrocarbons which represent a signficant loss of desirable hydrocarbons with the CO.sub.2 and H.sub.2 S vent gases.
U.S. Pat. No. 3,837,143 describes simultaneous dehydration and sweetening of natural gas to produce therefrom a purified natural gas having a low dew point and a low sulfur content by using a normally liquid dialkylether of a polyalkylene glycol ether containing 2-15% water by weight in direct contact with the natural gas. In this process, the natural gas is significantly dry with respect to C.sub.2 + hydrocarbons. Example 1 illustrates a loss of 74% of C.sub.2 + hydrocarbons with the CO.sub.2 and H.sub.2 S vent stream while Example 2 shows a loss of 11.6% for C.sub.2 + hydrocarbons. These losses, when applied to a wet natural gas stream, indicate a significant economic penalty for sweetening wet gases with DMPEG.
U.S. Pat. No. 4,052,176 relates to a synthesis gas and teaches further purification thereof with dimethyl ether of polyethylene glycol to absorb remaining CO.sub.2, H.sub.2 S, and COS. In this process DMPEG is used to treat a stream that does not contain C.sub.2 + hydrocarbons.
U.S. Pat. No. 4,070,165 teaches sweetening a raw natural gas by countercurrent contact with a lean amine solution, dehydrating by contact with a dry glycol stream, and removal of heavier hydrocarbons (after depressurizing) by scrubbing with a lean hydrocarbon stream which is then fractionated to produce methane, ethane, and propane. Dimethyl ether of polyethylene glycol is mentioned as useful for both water and H.sub.2 S removal. The natural gases which are suitable for liquefaction and which exist at pressures higher than 800 psig are usually dry and contain few C.sub.2 + heavier hydrocarbons. This patent also teaches the preference of amines over DMPEG for removing the H.sub.2 S and CO.sub.2 contents of the raw natural gas stream in order to eliminate hydrocarbon losses with CO.sub.2 and H.sub.2 S vent streams.
As presented at the 59th Annual Gas Processor's Association Convention, Mar. 17-19, 1980, in a paper entitled "High CO.sub.2 -High H.sub.2 S Removal With SELEXOL Solvent" by John W. Sweny, the relative solubility in DMPEG of CO.sub.2 over methane is 15.0 while that of propane is 15.3. The relative solubility of H.sub.2 S over methane is 134 in DMPEG vs. 83 for normal pentane in DMPEG. The relative solubilities in DMPEG of iso and normal butanes and iso pentanes are in between those of propane and H.sub.2 S. Such data indicate that if CO.sub.2 and H.sub.2 S are present in a natural gas stream which contains C.sub.2 + heavier hydrocarbons which are desirable for petrochemical industry feedstocks, substantial quantities of C.sub.2 + hydrocarbons will be lost with CO.sub.2 and H.sub.2 S vent streams when the natural gas is treated with DMPEG.
Sweet natural gas is usually saturated with water at its ambient temperature which may have a range of 75.degree.-120.degree. F., so that its water content may vary from 20 pounds to more than 50 pounds per million standard cubic feet. However, difficulties are frequently met while pumping such natural gas unless the water content is reduced to a value of less than 12 pounds, preferably less than 7 pounds, of water per million standard cubic feet of natural gas. In terms of dew point, a natural gas having a dew point of 30.degree. F., preferably 20.degree. F. or lower, is generally considered safe for transportation in a pipeline. Dehydration can be carried out under a wide range of pressures from 15 to 5000 psig, but it is usually carried out at pipeline pressures of 500-1500 psig and generally near 1000 psig.
There is nevertheless a need for a process wherein ethane and heavier hydrocarbons and water can be simultaneously removed to a selected degree from methane contained in a sweet natural gas stream without inclusion of steps involving drying thereof. There is further a need for a process wherein propane and heavier hydrocarbons can be extracted from a sweet natural gas stream without the need to extract significant quantities of ethane. There is further a need for a process wherein any natural gas, from very sour to entirely sweet, can be handled by the same equipment while simultaneously dehydrating the gas and recovering the heavier hydrocarbons.